Topping cycle & calculations

  Topping cycle & calculations


A Co-generation system can be classified as either a topping cycle or a bottoming cycle on the basis of sequence of energy generated & use.

 In a topping cycle, the fuel supplied is used to first produce power and then thermal energy, which is the by-product of the cycle and is used to satisfy process heat requirements.

 In a topping cycle, a primary heat source, such as a gas turbine or an internal combustion engine, is used to drive a generator and produce electricity. The primary cycle typically operates at higher temperatures and generates high-pressure and high-temperature exhaust gases.

 The exhaust gases from the topping cycle are then directed to a waste heat recovery boiler or a heat exchanger, where their residual heat is captured. This waste heat is then used to produce steam, which drives a steam turbine or an organic Rankine cycle (ORC) turbine in the bottoming cycle.

 Topping cycles are commonly used in combined cycle power plants, where they offer improved efficiency and performance compared to standalone gas turbines or internal combustion engines. The integration of a bottoming cycle allows for the utilization of waste heat, maximizing the overall energy output of the system.

 In a bottoming cycle, the primary fuel used produces high temperature thermal energy and the heat rejected from the process is used to generate power through a heat recovery Boiler & Turbo generator.

 Bottoming cycles are suitable for manufacturing processes that require heat at high temperature in furnaces & kiln and reject heat at significantly high temperatures.

 The bottoming cycle operates at lower temperatures and utilizes the waste heat energy to generate additional power. By extracting energy from the waste heat, the topping cycle achieves higher overall efficiency compared to a single-cycle power generation system.

 Topping cycle calculation:

 A Co-generation facility is defined as one, which simultaneously produces two or more forms of useful energy such as electrical power and steam, electric power and shaft (mechanical) power, etc.” The project may qualify to be termed as a co-generation project, if it is in accordance with the definition and also meets the qualifying requirement outlined below:

 Topping cycle mode of co-generation – Any facility that uses non-fossil fuel input for the power generation and also utilizes the thermal energy generated for useful heat applications in other industrial activities simultaneously.

 For the co-generation facility to qualify under topping cycle mode, the sum of useful power output and one half the useful thermal output be greater than 45% of the facility’s energy consumption, during season.”

Read >>>>Powerplant O&M reference books

Following inputs required for calculation of topping cycle:

  • Fuel consumption
  • Fuel GCV
  • Steam given to processes & their heat content
  • Power generation

Topping cycle is calculated by using following formula

 TC Eff = (Sum of total heat supplied to process in kcal X 50% + Total electricity generated in kcal) X 100 / Fuel energy


 A 44 MW Co-generation plant is operating at 41 MW load and utilizing bleed & extraction steam for process heating. Calculate the topping cycle efficiency

The inputs required are as below

Sl No





Boiler fuel consumption




Fuel GCV




Process-1 steam flow




Process steam-1 enthalpy




Process-2 steam flow




Process steam-2 enthalpy




Power generation




Total heat content in input fuel = 85 X 1000 X 2250 =191250000 kcal

Heat content in process-1 steam = 12 X 1000 X 740 =8880000 kcal

Heat content in process-2 steam = 170 X 1000 X 653 =111010000 kcal

Power generation in kcal = 41 X 1000 X 860 = 35260000 kcal

 TC Eff = (Sum of total heat supplied to process in kcal X 50% + Total electricity generated in kcal) X 100 / Fuel energy

TC Eff = ((8880000+111010000) X 50% + 35260000) X 100 / 191250000

 TC eff = 49.78%


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Calculation of pressure drop in steam and water lines

 Calculation of pressure drop in steam and water lines

 The pressure drop in a water & steam lines refers to the decrease in pressure that occurs as water/steam flows through a pipe or conduit due to factors such as friction and flow resistance. Several factors influence the magnitude of pressure drop in a water line:

Pipe Characteristics: The diameter, length, and roughness of the pipe impact the resistance to flow and consequently the pressure drop. Smaller diameter pipes and longer pipe lengths tend to result in higher pressure drops. Additionally, rougher pipe surfaces create more friction and increase pressure drop compared to smoother surfaces.

Flow Rate: The rate at which water/steam flows through the pipe affects the pressure drop. Higher flow rates generally result in higher pressure drops due to increased frictional resistance.

Fluid Properties: The physical properties of the water/steam being transported, such as viscosity and density, can influence the pressure drop. However, for water at typical temperatures and pressures, these effects are usually negligible.

 Pipe Fittings and Valves: The presence of fittings, such as elbows, bends, valves, and other obstructions in the water line, can contribute to pressure drop. These components disrupt the flow and introduce additional resistance.

 It's important to note that pressure drop calculations for steam lines can be complex and require a comprehensive understanding of steam properties and fluid dynamics.

 Pressure drop in water line:

Head loss in water line for turbulent flow is given as

Head loss in meter = 4fLV2 / (2gD)

 Where, f = Friction loss in pipe, generally varies from 0.005 to 0.007

L = Pipe length

D = Diameter of the pipe

g = Acceleration due to gravity, 9.81 m/s2

V = Velocity of the fluid


A Boiler feed pump is delivering feed water flow 50 TPH to the boiler at a distance of 70 meter.The steam drum height is 38 meter from pump suction.Calculate the pressure drop in water line, assume pipe line size is 80 NB, water density 980 kg/m3 & neglect the other losses from pipe line fittings.

 Feed water flow in m3/sec = 50 000 kg/hr / 980 kg/m3 = 51.02 m3/hr =0.014 m3/sec

Area in side the pipe line = 3.142 X 0.082/4 = 0.05 M2

Feed water velocity,V =  Flow / Area = 0.014 / 0.005 =2.78 m/sec

 Then, head loss, H = 4 X 0.005 X 38 X 2.782 / (2 X 9.81 X 0.08)

Head loss, H = 3.75 meter

 Minimum head required to lift the water up to steam drum, considering pressure drop in feed water control valve is 8 kg/cm2

 H = 3.75+80+38 =121.75 meter

 Pressure drop in steam line:

Head loss in meter = 2fLdV2 / (500gD)

(Density of water is 500 times more than steam at atmospheric pressure)

Where, f = Friction loss in pipe, generally varies from 0.005 to 0.007

L = Pipe length

D = Diameter of the pipe

g = Acceleration due to gravity, 9.81 m/s2

V = Velocity of the fluid

Read >>>Powerplant O&M reference books

 Example: Turbine inlet steam flow is 100 TPH & the distance between Boiler MSSV & Turbine MSSV is 82 meter.The seam pressure & temperature are 65 kg/cm2 and 490 deg C respectively.Calculate the pressure drop in steam line.

 Density of steam at above parameters = 17 kg/m3

Steam flow in m3/sec = 100 X 1000 kg/hr / 17 kg/m3=5882.35 m3/hr = 1.63 m3/sec

Assume main steam velocity being 45 m/sec

Pipe inside area A = Flow / Velocity = 1.63/45 =0.0362 m2

Now, calculate pipe diameter , A = 3.142 X D2/4

D = SQRT (0.036 X 4/3.142) = 0.214 meter = 214 mm

Now, Pressure drop H =(2 X 0.005 X 82/0.224) X (17/500) X (452/9.81) =25.7 m = 2.57 kg/cm2

For read>>>>Powerplant and calculations

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Droop and isochronous mode operation of steam Turbine

 Droop and synchronous modes are two operating modes commonly used in turbine control systems, particularly in the context of electrical power generation. These modes help regulate the speed and power output of the turbine to maintain stability in the electrical grid.

 Droop Mode Operation:

In droop mode, the turbine operates with a speed or frequency droop characteristic. Speed droop refers to the decrease in turbine speed as the load increases, while frequency droop refers to the decrease in electrical frequency. This mode allows multiple turbines or generators to share the load in a grid.

 In droop mode, the turbine's governor control system a

djusts the fuel supply to the turbine based on the difference between the actual speed/frequency and a reference speed/frequency. As the load on the turbine increases, the speed or frequency decreases slightly, which causes the governor to open the fuel valve and increase the steam flow, compensating for the increased load. Similarly, when the load decreases, the speed or frequency increases, resulting in a reduction in fuel supply.

 Droop mode operation allows for load sharing among multiple turbines or generators. Each unit operates at a slightly different speed or frequency, which helps balance the load in a grid. The speed or frequency difference between units is known as the droop setting, and it determines how the load is shared between them.

 Key features of droop mode operation:

 Speed Control: The turbine's speed is adjusted to maintain a stable power output as per the grid's load demand. As the load increases, the turbine's speed decreases.

 Frequency Regulation: The frequency of the electrical output from the turbine is dependent on the load. As the load increases, the frequency decreases, and vice versa.

 Load Sharing: Multiple turbines operating in droop mode share the load in proportion to their capacities. Each turbine adjusts its speed based on the droop characteristic to contribute its fair share to the overall power demand.

 Load control in droop mode

 While STG is connected with grid this mode becomes active.If, STG is connected to other STG, but without grid paralleling then also this mode can be made active.

Generally 4 to 6% of droop is set for electro hydraulic control system.

By taking 4% droop as an example, 1% droop corresponds to 25% load, 2% droop is equivalent to 50% & 4% refers to 100% load.

In such controllers mode,load will be input & based on it speed will be adjusted.

 For example:

A 25 MW turbine has 8500 RPM and has droop set 4%.If Turbine is operating at 12.5 MW then controller speed set point is

 8500 + 2% X 8500 = 8670 RPM

 If it is operating on full load, then speed setting will be

 8500 + 4% X 8500 = 8840 rpm

 Isochronous mode operation:

 In isochronous mode, the turbine operates at a constant speed or frequency regardless of the load variations. In this mode, the governor control system works to maintain a steady speed or frequency by adjusting the fuel supply to the turbine.

Read >>>>Powerplant O&M reference books

 The governor closely monitors the speed or frequency and makes minute adjustments to the fuel valve to counteract any changes caused by load fluctuations. As a result, the turbine operates at a constant speed or frequency, providing a stable power output.

 Isochronous mode is typically employed when maintaining a constant frequency is critical, such as in certain industrial applications or when connected to a sensitive electrical grid that requires precise frequency control.

 Key features of isochronous mode operation:

Read Generator and Turbine inter tripping

 Speed Control: The turbine's speed is regulated to remain constant, regardless of the load demand. As the load increases or decreases, the turbine adjusts its power output while maintaining a constant speed.

 Frequency Regulation: The turbine's output frequency is maintained at a constant level, typically the nominal frequency of the electrical grid. The turbine adjusts its power output to match the load demand while keeping the frequency stable.

 Load Balancing: In isochronous mode, each turbine connected to the grid contributes to the load based on its power capacity. The turbines collectively adjust their power outputs to meet the total load demand while maintaining a constant speed and frequency.

 It is to be noted that,when STG runs in parallel mode, it remains in droop mode.If the STG is connected to to grid, as soon as STG comes out from grid (Island mode), auto changeover occurs from droop mode to synchronous mode.Then STG controls speed only

For more >>>>read Powerplant and calculations

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Effect of moisture content in steam Turbines

Effect of moisture content in steam Turbines

 When steam passes through a turbine, it undergoes expansion and releases energy, which is harnessed to generate power. However, if the steam contains water droplets or moisture, it can have detrimental effects on the turbine blades. As the steam expands and flows through the turbine stages, the droplets can impinge on the blades, leading to erosion, pitting, or damage.

 The churning effect typically occurs in the last few stages of the turbine, where the steam is at lower pressure and velocity. At these stages, any remaining liquid particles in the steam are prone to separation from the gas phase and can cause erosion on the turbine blades.

Read Power plant O&M reference books

 Moisture content in steam  leads into the following problems:

 Erosion: The high-speed impact of liquid droplets on the turbine blades can cause erosion, leading to damage and reduced efficiency over time. Erosion can wear down the blade surfaces, affecting their aerodynamic shape and performance.

 Vibrations: The churning effect can induce vibrations in the turbine rotor and other components. Excessive vibrations can cause mechanical stress and fatigue, leading to increased wear and potential failures.

 Loss of efficiency: The presence of liquid droplets in the steam reduces the effective energy transfer from the steam to the turbine blades. This can result in a decrease in overall turbine efficiency and power output.

 To mitigate the this effect and protect the turbine blades, several measures can be implemented:

 Proper design of steam Turbine & blading to ensure proper expansion of steam in blades.Blade Design: Turbine blades can be designed to minimize the impact of churning. This can include using erosion-resistant materials, shaping the blades to minimize droplet impingement, and providing protective coatings.

 Drainage Systems: Proper design and implementation of drainage systems within the turbine help remove condensed water and moisture effectively

 Proper operation of the Turbine & maintaining steam parameters as per design

 To mitigate the moisture content in steam and its negative consequences, steam turbines are equipped with various mechanisms and components, including steam separators, moisture separators, and steam dryers. These devices help remove or reduce the moisture content in the steam before it enters the turbine, ensuring better steam quality and minimizing the chances of churning.

 Proper design, operation, and maintenance practices, such as regular inspection and cleaning of turbine components, are essential to prevent or minimize the churning effect and maintain optimal turbine performance and longevity.

10-Difference between fixed nozzle and Variable nozzle de-super heating


 De-superheating is the process of reducing the temperature of superheated steam. This is typically achieved by injecting a cooling medium, such as water, into the steam flow. The nozzles used in the desuperheating process can be classified as either variable nozzle or fixed nozzle de-superheaters. Here's

 The differences between these two types are:

Sl No.

Variable nozzle de-super heater

Fixed nozzle de-super heater


Variable nozzle desuperheating systems have adjustable nozzles that allow for controlling the flow rate of the cooling medium injected into the steam flow.

Fixed nozzle desuperheating systems have non-adjustable nozzles, meaning the cooling water flow rate and the degree of desuperheating are fixed


The nozzle opening can be adjusted to vary the amount of cooling water injected, thereby controlling the degree of desuperheating and achieving the desired steam temperature.

Separate control valve is required to adjust the water flow


More flexibility in adjusting the cooling water flow rate and achieving precise temperature control.

Not much accuracy in temperature control


Variable nozzle desuperheating systems are often used in applications that require tight temperature control,

USed where there is much tolerance in temperature control,

Ex: In process industries

They are commonly used in applications where a constant degree of desuperheating is sufficient, such as in industrial processes with steady steam loads or in small-scale power plants.


Complex design

Simple design


More costlier than fixed nozzle de-super heaters

Less costlier


Little bit complicated operation

Simple operation


Can be used for variable inlet flow & temperature

Used only for fixed flow & temperature


Size of nozzle is variable

Size of nozzle is fixed


Maintenance is difficult & costlier

Maintenance is simple & cheaper

 The choice between a variable nozzle and fixed nozzle desuperheater depends on factors such as the required temperature control accuracy, steam flow variability, plant operating conditions, and budget considerations. Variable nozzle desuperheaters are often preferred in applications where precise temperature control and flexibility are crucial, while fixed nozzle desuperheaters can be suitable for applications with relatively stable operating conditions and lower cost requirements.

15-Emergencies in power plant operation

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